Devices, systems, facilities, and processes for liquefied natural gas production

Abstract

Devices, systems, and methods for liquefied natural gas production facilities are disclosed herein. A liquefied natural gas (LNG) production facility includes a liquefaction unit and a gas turbine. The liquefaction unit condenses natural gas vapor into liquefied natural gas. Fuel to the gas turbine contains at least about 90% hydrogen by volume.

The invention is claimed as follows: 
     
       1. A liquefied natural gas (LNG) production facility comprising:
 an acid gas removal unit configured to accept raw feed natural gas and to generate an acid gas stream, a flash gas stream, and a purified natural gas stream, wherein the acid gas stream is directable to a sequestration compression unit; 
 a heavies removal unit configured to receive a dry purified natural gas stream from a dehydration unit and to produce a liquid condensate product and a vapor product; 
 a condensation storage tank configured to receive the liquid condensate product from the heavies removal unit, and to allow for the venting of boil off gas (BOG); 
 a liquefaction unit that condenses natural gas vapor into liquefied natural gas; 
 a gas turbine; 
 an on-site hydrogen generation unit that provides hydrogen to the gas turbine, wherein the hydrogen generation unit is a steam reformer; 
 at least one capture unit that generates a CO2-rich stream from products of the steam reformer; 
 the sequestration compression unit configured to compress and convey at least one CO2-rich stream from a capture unit, towards a sequestration site, thereby reducing the overall emissions from the LNG facility; 
 an LNG storage tank configured to receive and store LNG from the liquefaction unit, and to allow for the venting of BOG; and 
 an LNG loading facility configured to receive LNG from the LNG storage tank and to transfer LNG to a marine vessel comprising a marine LNG storage tank, the LNG loading facility further configured to allow for the venting of BOG, 
 wherein BOG from at least one of the condensation storage tank, the LNG storage tank, and the LNG loading facility is directable as feed to the steam reformer; and 
 wherein a fuel to the gas turbine contains at least about 90% hydrogen by volume. 
 
     
     
       2. The LNG facility of  claim 1 , wherein the sequestration site comprises an underground geological formation comprising an at least partially depleted hydrocarbon reservoir. 
     
     
       3. The LNG facility of  claim 1 , wherein the sequestration site comprises a region on top of a seabed, said region located at a depth greater than about 3.0 kilometers below sea level. 
     
     
       4. The LNG facility of  claim 1 , wherein the sequestration site comprises a region below a seabed. 
     
     
       5. The LNG facility of  claim 1 , wherein the flash gas stream is directable to the sequestration compression unit. 
     
     
       6. The LNG facility of  claim 1 , wherein the flash gas stream is directable to the steam reformer for use as a feedstock to the reformer. 
     
     
       7. The LNG facility of  claim 1 , wherein the sequestration compression unit comprises a compressor driven by steam from the steam reformer. 
     
     
       8. The LNG facility of  claim 1 , wherein the capture unit includes an amine absorber and liquid amine absorbent for absorbing CO2, wherein the steam reformer generates excess steam, and wherein the excess steam is directable to the capture unit to provide heat for regenerating the liquid amine absorbent. 
     
     
       9. The LNG facility of  claim 1 , wherein the capture unit includes a chilled ammonia process for absorbing CO2, wherein the steam reformer generates excess steam, and wherein the excess steam is directable to the capture unit to provide heat for regenerating the ammonia absorbent. 
     
     
       10. The LNG facility of  claim 1 , wherein the acid gas removal unit includes an amine absorber and liquid amine absorbent for absorbing CO2, wherein the steam reformer generates excess steam, and wherein the excess steam is directable to the acid gas removal unit to provide heat for regenerating the liquid amine absorbent. 
     
     
       11. The LNG facility of  claim 1 , wherein the acid gas removal unit includes a chilled ammonia process for absorbing CO2, wherein the steam reformer generates excess steam, and wherein the excess steam is directable to the acid gas removal unit to provide heat for regenerating the ammonia absorbent. 
     
     
       12. The LNG facility of  claim 1 , further comprising the dehydration unit including a solid adsorbent, the dehydration unit configured to receive the purified natural gas stream from the acid gas removal unit and to provide the dry purified natural gas stream, wherein the steam reformer generates excess steam, and wherein the excess steam is directable to the dehydration unit to provide heat for regenerating the solid adsorbent. 
     
     
       13. The LNG facility of  claim 1 , wherein the steam reformer generates excess steam, and wherein the excess steam is directable to the sequestration unit, and wherein the sequestration compression unit comprises a compressor driven by the excess steam from the steam reformer. 
     
     
       14. The LNG facility of  claim 1 , wherein the steam reformer generates excess steam, and wherein the excess steam is directable to drive a compressor. 
     
     
       15. The LNG facility of  claim 1 , wherein the sequestration compression unit comprises a compressor driven by an electric motor. 
     
     
       16. The LNG facility of  claim 1 , wherein the sequestration compression unit comprises a compressor driven by the gas turbine. 
     
     
       17. The LNG facility of  claim 1 , wherein the sequestration compression unit comprises a compressor driven by a hydrogen turbine configured to be driven by hydrogen from the steam reformer. 
     
     
       18. The LNG facility of  claim 1 , wherein BOG from each of the condensation storage tank, the LNG storage tank, and the LNG loading facility is directable as feed to the steam reformer. 
     
     
       19. The LNG facility of  claim 1 , further comprising a marine vent system adapted to receive marine vessel tank gas from a marine LNG storage tank of a marine vessel, and to direct the marine vessel tank gas to feed any of:
 (a) the sequestration compression unit; 
 (b) a fuel gas conditioning unit; and 
 (c) the steam reformer, 
 wherein the marine vessel tank gas comprises BOG from LNG, CO, CO2, N2 or mixtures thereof. 
 
     
     
       20. The LNG facility of  claim 4 , wherein the seabed is located at a depth greater than about 3.0 kilometers below sea level. 
     
     
       21. The LNG facility of  claim 1 , where the facility is configured to receive natural gas from a pig recovery system and to direct the natural gas as feed to the steam reformer. 
     
     
       22. The LNG facility of  claim 1 , wherein the facility is configured to direct BOG from at least one of the condensation storage tank, the LNG storage tank, and the LNG loading facility to the sequestration compression unit.